1. Field of the Invention
This invention relates generally to rotary drill bits useful for subterranean drilling, or forming boreholes in subterranean formations. More particularly, the invention pertains to rotary drill bits, also referred to as drag bits, having improved directional control and wear resistance.
2. State of the Art
Rotary drill bits for drilling oil, gas, and geothermal wells, and other similar uses typically comprise a solid or composite metal body having a lower cutting face region and an upper shank region for connection to the bottom hole assembly of a drill string formed of conventional jointed tubular members which are then rotated as a single unit by a drilling rig. Alternatively, rotary drill bits may be attached to a bottom hole assembly including a downhole motor assembly which is in turn connected to an essentially continuous tubing, also referred to as coiled, or reeled, tubing wherein the downhole motor assembly rotates the drill bit. Typically, the bit body has one or more internal passages for introducing drilling fluid, or mud, to the cutting face of the drill bit to cool cutters provided on the face of the drill bit and to facilitate formation chip and formation fines removal. The sides of the drill bit typically include a plurality of radially extending gage pads which have an outermost surface which is of substantially constant diameter and generally parallel to the central longitudinal axis of the drill bit. The gage pads generally contact the wall of the bore hole being drilled in order to support and provide guidance of the drill bit as it advances along a desired cutting path, or trajectory.
As known within the art, certain gage pads of the total number of gage pads provided on a given drill bit are selected to be provided with outwardly extending replaceable cutting elements installed on the gage pad allowing the cutting elements to engage the formation being drilled and to assist in providing gage-cutting, or side-cutting, action therealong. One type of cutting element provided on selected gage pads in the past, referred to as inserts, compacts, and cutters, have been known and used for a relatively long time on the lower cutting face for providing the primary cutting action of the bit. These cutting elements are typically manufactured by forming a superabrasive layer, or table, upon a sintered tungsten carbide substrate. As an example, a tungsten carbide substrate having a polycrystalline diamond (PCD) table or cutting face, is sintered onto the substrate under high pressure and temperature, typically about 1450 to about 1600xc2x0 C. and about 50 to about 70 kilobar pressure to form a polycrystalline diamond compact (PDC) cutting element or PDC cutter. During this process, a metal sintering aid or catalyst such as cobalt may be premixed with the powdered diamond or swept from the substrate into the diamond to form a bonding matrix at the interface between the diamond and substrate.
The above described PDC cutting elements, or cutters, when installed on selected gage pads instead of on the lower portion of the face of the drill bit, are generally referred to as being gage cutters as the cutting element cuts the outermost gage dimension, or diameter, for the particular drill bit in which the cutters are installed. That is the cutters, or more particularly the cutting surfaces thereof, being positioned at the further-most radial distance from the longitudinal centerline of the drill bit, i.e., the outer periphery of the drill bit, will define the final diameter of the bore hole being formed as a result of the drill bit engaging, cutting, and displacing the subterranean formation in the forming of a well bore.
In addition to the above described PDC cutters being provided on selected gage pads, it is also known that other types of cutting elements can be provided on selected gage pads. For example, it is known that broaching of a radially outwardly facing surface of a gage pad can be performed to provide a plurality of longitudinally extending ribs having abrasive particles, such as natural or synthetic diamonds, embedded therein and wherein the ribs protrude radially outwardly from the surface of the gage pad a preselected distance. Furthermore, it is also known that all of the gage pads of a given drill bit can be provided with such raised generally longitudinally extending ribs having abrasive particles embedded therein and which are formed by way of broaching. However, it is important to note that in such cases that all the gage pads of a given drill bit were provided with such raised ribs embedded with abrasives, the gage pads were provided with the same level or degree of aggressiveness. That is, the raised ribs contained the same density of abrasive particles embedded therein. Further, the raised ribs extended radially outwardly from the gage pad essentially the same preselected distance so as to provide each gage pad with a constant, or same, degree of gage-cutting aggressiveness.
Especially during horizontal and directional drilling operations, cutters, or cutting elements, whether located on the face or gage of the drill bit, are repeatedly subjected to very high forces from a variety of directions and are also subjected to relative high temperatures during drilling operations and may fracture, delaminate, and/or spall to an unuseable state in a relative short time. Such degradation of the cutters results in lost drilling time, and further results in expensive rig time being expended on pulling the drill string in order to replace the worn drill bit with a new or previously repaired substitute bit, and then re-running the drill string back into the borehole in order for drilling to be resumed.
Another problem which occurs related to the horizontal drilling of extended reach boreholes, which are usually begun as generally vertical holes but which are eventually curved to follow a horizontal or tilted path, or trajectory, in order to reach a targeted stratum of formation, or pay zone is that, in many cases, the borehole may be curved, or deviated, as much as 90 degrees, or more. Thus, it is often very difficult to place the bit in the desired orientation at a particular depth within a selected formation stratum, or zone, particularly if the stratum is relatively thin. To achieve a such a curved, or radiused, bore hole, the drill bit must be directionally controllable in order to be continuously xe2x80x9caimedxe2x80x9d or guided at an angle with respect to the generally vertical portion of the borehole, usually located near the surface. Furthermore, the drill bit must necessarily have a degree of side, or gage, cutting capability to enlarge the borehole diameter slightly beyond the nominal diameter of the gage pads. Thus, the geometry of a drill bit must be such that it may be canted within the borehole, but not so much that it drifts to one side and forms an enlarged or out-of-round bore hole in an uncontrolled fashion or in an undesired direction. Such drifting commonly occurs with drill bits designed for short radius curves and, in some cases, with bits designed to produce medium radius curves. Furthermore, it is important that the quality, or surface smoothness and roundness of the bore hole be maintained within an acceptable range to not only facilitate the introduction and extraction of drill string and various down hole tools, but also for completing the well by the introduction and cementing of production casing within the bore hole.
For the purposes of the present specification, a long radius curve will be defined as one which makes an arc, or curve, approaching, obtaining, or surpassing an angle of approximately 90 degrees (e.g. from vertical to horizontal) and has a radius of curvature exceeding approximately 1000 foot (approximately 305 meters). A medium radius curve will be defined as one which makes an arc, or curve, approaching, obtaining, or surpassing an angle of approximately 90 degrees with an approximate 300-1000 foot (approximately 91-305 meters) radius of curvature. A short radius curve is one which makes an arc, or curve, approaching, obtaining, or surpassing an angle of approximately 90 degrees with a short radius of curvature, i.e. less than approximately 300 feet (approximately 91 meters) and, in extreme cases, as approximately 20 feet (approximately 6 meters). Generally, any acceptable margins of error with respect to reaching target depths are directly proportional to the radius of curvature of the borehole. That is, the smaller a given radius of curvature that a borehole is to have, the associated acceptable margin of error in drilling to a specified depth is corresponding smaller, necessitating that the drill bit not significantly deviate from the pre-determined path, or trajectory, in order to reach the targeted zone, or zones, of interest. FIG. 23 of the drawings provides an illustration of such different radiused bore hole curvatures. For example, and as will be further described herein, a long-radiused curvature is designated as 78, a medium-radiused curvature is designated as 80, and a short-radiused curvature is designated as 82.
In U.S. Pat. No. 5,163,524 of Newton, Jr. et al., a rotary drill bit is shown with a plurality of circumferentially spaced gage pads, some of the gage pads having gage cutters disposed thereon and with some gage pads being completely free of cutters. According to the Newton et al. ""524 patent, the gage pads free of cutters are fabricated to be more abrasion resistant than the gage pads having cutters thereon. Furthermore, according to Newton et al., by providing a drill bit having some gage pads free of cutters, upon a bit experiencing laterally imbalanced forces, the gage pads free of cutters which happen to be engaging the formation of earth at the time will impart or pass on such laterally imbalanced forces directly to the formation in accordance with the ""524 Newton et al. patent by way of every third gage which is free of gage-cutters and thereby inhibit the walking, or wandering, of the drill bit within the bore hole.
In U.S. Pat. No. 5,651,421 issued to Newton et al., a rotary drill bit is disclosed having a plurality of alternating and circumferentially spaced primary and secondary blades each having cutters thereon. The Newton et al. ""421 patent discloses that preferably each primary and secondary blade is provided with a corresponding primary and secondary gage pad which bear on the side wall of the bore hole being drilled. The Newton et. al. ""421 patent further provides that the primary gage pads may include bearing and/or abrading elements which are flush with the surface of the gage pad while each secondary gage pad may include gage cutters which project outwardly beyond the surface of the gage pad for removal of the surrounding formation.
However, the need continues to exist for a drill bit having properties which provides, especially when drilling short or medium radius boreholes, a minimum amount of drifting from a preselected trajectory, which minimizes wear of the drill bit, which cuts at an enhanced rate, and which is configurable to an optimum design especially suited to drill, or bore, into particularly targeted formations of earth at a predetermined trajectory to a predetermined depth.
A yet further need exists for a drill bit, especially when drilling short or medium radius boreholes, which can provide a well bore of an acceptable quality. That is, it is desirable that upon a bore hole being drilled, it have a generally constant roundness, or concentricity, and that the surface of the bore hole have an acceptable level of surface smoothness, or in other words, the surface of the bore hole will not be unacceptably rough, have unacceptable irregularities, or have an unduly distorted geometry.
The present invention includes a rotary drill bit for subterranean drilling exhibiting improved directional control and enhanced borehole quality.
The rotary drill bit of the present invention is especially suitable for directional drilling of deviated, horizontal, extended reach, and other directional wellbores, with improved side, or gage, cutting ability to enable turns of shorter radius and yet with improved resistance to drifting away from a desired trajectory.
The rotary drill bit of the present invention further has the ability to enhance the geometrical and surface quality of the bore hole.
The rotary drill bit of the invention which is also readily configurable for enhanced cutting in specific formations.
The invention comprises a drill bit with a selected number of gage pads preferably ranging from about four to ten or more, depending primarily upon the gage diameter of the bit. At least one cutting element, or aggressive surface, is installed on or is proximate to, each of the gage pads. Gage pads with highly aggressive cutting element surfaces, or on-gage pad cutting elements, or alternatively or in addition to, off-gage pad cutting elements, are alternated with gage pads having less aggressive cutting element surfaces, or on-gage pad cutting elements, or alternatively or in addition to, off-gage pad cutting elements arranged in a preselected circumferential pattern. The degrees of aggressiveness of the alternating gage pads, or cutting elements exclusively associated with each gage pad, may be varied widely, and are controlled and influenced by a number of factors, including but not limited to the radial exposure of the cutting elements, cutting element shape, size, back rake and side rake angles, quantity of individual cutting elements, and shape of the cutting surfaces or edges of the cutting elements. The capability of controlled side, or gage, cutting is enhanced with the selection of the number of and relative positioning of the more aggressive gage pads and associated gage cutting elements while the demonstrated wear characteristics of the rotary bit is maintained, or improved, by the provided alternating less aggressive gage pad.
For any formation of earth through which a bore hole is to be drilled, there exists one or more combinations of aggressiveness-affecting factor selections which will provide a minimum overall cost, a minimum amount of non-productive drilling rig time, a maximum drilling rate, maximum bit life, optimal side cutting capability, minimal distortion or deviation from a desired bore hole geometry, and thus providing an over all enhancement of bore hole quality.
Drill bits embodying, and constructed in accordance with the present invention, may be optimally designed or specifically modified for increasing the drilling into particular formations by taking into account at least the above identified factors.